Fortnightly - Locational marginal pricehttp://www.fortnightly.com/tags/locational-marginal-price
enRegulatory Rounduphttp://www.fortnightly.com/fortnightly/2004/12/regulatory-roundup
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Bruce Radford</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><strong>Bruce W. Radford</strong> is editor in chief of <em>Public Utilities Fortnightly</em>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - December 2004</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p><b>Path 15 Upgrade. </b>California ISO (Cal-ISO) runs into opposition with its unprecedented plan in Tariff Amendment 63 to make the Western Area Power Administration (WAPA) a "partial" participating transmission owner in the ISO, in trade for WAPA's 10 percent capacity interest (150 MW) in the Path 15 upgrade. Utilities complain that WAPA will receive a 10 percent share of FTRs and congestion revenues, though PG&amp;E and TransElect will have paid for 99.5 percent of the line construction costs. <i>FERC Dkt. Nos. EL04-133, ER04-1198, protests filed Sept. 29, 2004.</i></p>
<p><b>Gas Bypass Pipelines.</b> Oregon appeals court reverses a state public utility commission (PUC) order, says a group of industrial gas users would violate state law providing for exclusive utility franchise rights if it forms a cooperative to bypass the local gas distribution utility and construct a pipeline to deliver gas to its members at retail. <i>NW Nat Gas Co. v. Or. PUC, Nos. 01C-18514, Oct. 13, 2004</i><i>.</i></p>
<p><b>Power Line Communications.</b> Federal Communications Commission (FCC) OKs new rules for BPL (Broadband Over Power Line) systems to create a competitive regulatory framework for the use of existing electric utility lines to provide high-speed communications. <i>ET Dkt. Nos. 04-36, 03-104, Oct. 14, 2004.</i></p>
<p><b>Gen Station Power Needs.</b> Duke Energy said it could support Cal-ISO's claim that it was "stretched thin," and wanted first to gather and study data from power producers before investing money to change its billing and metering protocols and software on netting of on-site station power against unit output. Duke had complained to FERC to force Cal-ISO to conform to FERC precedent to permit its Moss Landing units to net their draws of station power against output from any other unit under common ownership, even if not operating instantaneously, and even if the two units are not directly interconnected. <i>FERC Dkt. No. EL04-130, reply filed Oct. 7, 2004.</i></p>
<p><b>ISO Retail Service. </b>The Maine PUC said it would not require the New England Power Pool (NEPOOL) or ISO New England (ISO-NE) to obtain a utility license to serve an individual consumer (MPEU, or "Market Participant End User") with generation supply taken directly from the New England regional wholesale market. But a private power producer, trader or affiliate who facilitates the deal would require a license as a competitive retail energy provider. <i>Morin Brick Co., Dkt. No. 2004-345, Aug. 27, 2004.</i></p>
<p><b>Renewable Energy Portfolios. </b>California appeals court overturns state PUC order that required electric utilities to pay costs upfront for upgrading regional power grid to accommodate sources of renewable energy to comply with a state law passed in 2002 that mandates a one-percent-per-year increase in renewable energy portfolios maintained by public utilities. <i>So.Cal.Ed. v. CPUC, Cal.App.2d Dist., No. B171050, Aug. 31, 2004.</i></p>
<p><b>Gas Supply Risk. </b>Regulators in Virginia were checking whether to allow Washington Gas Light to reclaim gas customers that had chosen competitive retail service from Metromedia Energy Inc. or to demand a larger security deposit from MME, to cover risk from higher futures prices and MME's increased share of the utility's design-day load.<i> Va.S.C.C. Case No. PUE-2003-00536.</i></p>
<p><b>Fuel Cost Hedging.</b> Georgia PSC rules that Savannah Elec. &amp; Power no longer needs any special financial incentive to operate its fuel cost hedging program, decides to flow fuel cost savings from hedging activities to ratepayers, ending prior practice of sharing 25% of such gains with company shareholders. <i>Dkt. No. 19042-U, Oct. 19, 2004.</i></p>
<p><b>Utility Supply Solicitations. </b>Ohio PUC OK's bidding process for FirstEnergy subsidiary Ohio Edison to solicit offers from power producers for energy supply, to assemble standard-offer portfolios for default retail customers. PUC appoints Charles River Associates to help analyze bids. No single bidder can win right to supply more than 65 percent of utility load. <i>Cause No. 04-1371-<br />EL-ATA, Oct. 6, 2004.</i></p>
<p><b>Provider of Last Resort (POLR).</b> The Pennsylvania PUC OK's three-year term with fixed prices for a POLR tariff for Duquesne Light, citing as irrelevant the utility's claim that it needed a six-year term to cut risk to help its unregulated affiliate buy the Sunbury plant. <i>Case No. P-00032071, Oct. 5, 2004.</i></p>
<p><b>Coal Seam Gas.</b> Utah Public Service Commission (PSC) orders Questar Gas to refund some $25 million collected from customers to cover the cost of processing coal-seam gas produced near Price, Utah, saying that the gas was incompatible with appliances and posed a danger to retail customers. <i>Dkt. Nos. 03-057-057 et al., Aug. 30, 2004.</i></p>
<p><b>Deceptive Marketing Practices.</b> Illinois Commerce Commission rules that private natural gas retailer Peoples Energy Services Corp. violated state law by inviting customers to lock in a fixed price (62 cents per therm) for more than a year, while reserving the right at any time to send a "pricing notice" to customers with a new higher rate that would be binding absent the customer's written objection within days. <i>Case No. 03-0592, July 21, 2004.</i></p>
<p><b>Renewable Portfolio Standards. </b>New Jersey BPU ok's a financing arrangement with the PJM RTO to develop and implement a Generator Attributes Tracking System (GATS) to identify qualifying resources and verify compliance with state programs to promote renewable energy.</p>
<p><b>Retail Electric Competition. </b>Citing significant market power in wholesale power supply, plus a dearth of alternative retail electric vendors, utility regulators in Virginia in a report to the governor (Sept. 1, 2004) questioned whether retail electric competition can bring lower power prices to consumers than would have been the case under traditional regulation.</p>
<p><b>Promotional Utility Advertising.</b> The Maine PUC dismissed a customer complaint that Central Maine Power's campaign of promoting the use of electric-consuming appliances violated the public interest by increasing environmental degradation and domestic dependence on foreign oil. <i>Dkt. No. 2004-481, Sept. 18, 2004.</i></p>
</div></div></div><div class="field field-name-field-article-category field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Category (Actual): </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/article-categories/energy-policy-legislation">Energy Policy &amp; Legislation</a></li><li class="taxonomy-term-reference-1"><a href="/article-categories/commission-watch">Commission Watch</a></li></ul></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-department field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Department: </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/department/commission-watch">Commission Watch</a></li></ul></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/0412-cvr_2.jpg" width="654" height="875" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
<div class="field-label">Tags:&nbsp;</div>
<div class="field-items">
<a href="/tags/aep">AEP</a><span class="pur_comma">, </span><a href="/tags/alliant">Alliant</a><span class="pur_comma">, </span><a href="/tags/ameren">Ameren</a><span class="pur_comma">, </span><a href="/tags/american-electric-power">American Electric Power</a><span class="pur_comma">, </span><a href="/tags/aps">APS</a><span class="pur_comma">, </span><a href="/tags/atc">ATC</a><span class="pur_comma">, </span><a href="/tags/central-maine-power">Central Maine Power</a><span class="pur_comma">, </span><a href="/tags/charles-river-associates">Charles River Associates</a><span class="pur_comma">, </span><a href="/tags/cinergy">Cinergy</a><span class="pur_comma">, </span><a href="/tags/citi">Citi</a><span class="pur_comma">, </span><a href="/tags/comed">ComEd</a><span class="pur_comma">, </span><a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/communication">Communication</a><span class="pur_comma">, </span><a href="/tags/consumers-power">Consumers Power</a><span class="pur_comma">, </span><a href="/tags/cost">Cost</a><span class="pur_comma">, </span><a href="/tags/dayton-power-light">Dayton Power &amp; Light</a><span class="pur_comma">, </span><a href="/tags/dominion">Dominion</a><span class="pur_comma">, </span><a href="/tags/duke-energy">Duke Energy</a><span class="pur_comma">, </span><a href="/tags/electric-transmission">Electric Transmission</a><span class="pur_comma">, </span><a href="/tags/exelon">Exelon</a><span class="pur_comma">, </span><a href="/tags/fcc">FCC</a><span class="pur_comma">, </span><a href="/tags/federal-communications-commission">Federal Communications Commission</a><span class="pur_comma">, </span><a href="/tags/federal-communications-commission-fcc">Federal Communications Commission (FCC)</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission-ferc">Federal Energy Regulatory Commission (FERC)</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/firstenergy">FirstEnergy</a><span class="pur_comma">, </span><a href="/tags/ge">GE</a><span class="pur_comma">, </span><a href="/tags/illinois-commerce-commission">Illinois Commerce Commission</a><span class="pur_comma">, </span><a href="/tags/iso">ISO</a><span class="pur_comma">, </span><a href="/tags/iso-new-england">ISO New England</a><span class="pur_comma">, </span><a href="/tags/iso-ne">ISO-NE</a><span class="pur_comma">, </span><a href="/tags/lge">LG&amp;E</a><span class="pur_comma">, </span><a href="/tags/lmp">LMP</a><span class="pur_comma">, </span><a href="/tags/locational-marginal-price">Locational marginal price</a><span class="pur_comma">, </span><a href="/tags/locational-marginal-prices">Locational marginal prices</a><span class="pur_comma">, </span><a href="/tags/maine-puc">Maine PUC</a><span class="pur_comma">, </span><a href="/tags/maps">MAPS</a><span class="pur_comma">, </span><a href="/tags/miso">MISO</a><span class="pur_comma">, </span><a href="/tags/new-jersey">New Jersey</a><span class="pur_comma">, </span><a href="/tags/ohio-edison">Ohio Edison</a><span class="pur_comma">, </span><a href="/tags/pge">PG&amp;E</a><span class="pur_comma">, </span><a href="/tags/pjm">PJM</a><span class="pur_comma">, </span><a href="/tags/questar">Questar</a><span class="pur_comma">, </span><a href="/tags/renewable">Renewable</a><span class="pur_comma">, </span><a href="/tags/renewable-energy">Renewable Energy</a><span class="pur_comma">, </span><a href="/tags/rto">RTO</a><span class="pur_comma">, </span><a href="/tags/transmission">Transmission</a><span class="pur_comma">, </span><a href="/tags/utah-public-service-commission">Utah Public Service Commission</a><span class="pur_comma">, </span><a href="/tags/wisconsin-public-service">Wisconsin Public Service</a> </div>
</div>
Wed, 31 Dec 2014 15:31:07 +0000meacott18781 at http://www.fortnightly.comNegawhat?http://www.fortnightly.com/fortnightly/2014/06/negawhat
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p><i>EPSA v. FERC:</i> How the court went wrong on demand response.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Bruce W. Radford</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Bruce Radford</b> is publisher and acting editor of <i>Public Utilities Fortnightly</i>. Reach him at <a href="mailto:radford@pur.com">radford@pur.com</a>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - June 2014</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>As I sit down to write, the U.S. Court of Appeals for D.C. Circuit only hours ago dropped a bombshell, declaring in the case of <i>EPSA v. FERC,</i> No. 11-1486, decided May 23, 2014 by a vote of 2-1, that Federal Energy Regulatory Commission Order 745 is completely null and void.</p>
<p>And for that clever bit of timing, waiting until Friday afternoon, so as not to roil markets, I applaud the court. But in forcing reporters back to their computer screens, to give up a portion of their Memorial Day holiday weekends in order to grind out a story to make their Tuesday deadlines, I can only curse.</p>
<p>You see, in treating demand response as the moral equivalent of electric generation, as it did in 2011 in Order 745 - that is, by rewarding forgone consumption with a payment equal to the going wholesale market price for day-ahead energy, known as the locational marginal price, or "full LMP," without any offset for "G" (that being the cost of buying energy that is thereby avoided) - FERC had sought to remove barriers and place DR on an equal footing with power plants. Congress in fact just a few years earlier had told the commission to do exactly that, in sec. 1252 of the 2005 EPACT law.</p>
<p>But no. Choosing not to buy electricity, the court said, is a retail transaction, every bit as much as buying. So when the regulator promises a payment or credit for forgone consumption, the court explained, he is setting a retail rate - just the same, and no different in concept, than fixing the per-kilowatt-hour charge we all see on our monthly power bills. And so the court ruled: "Because FERC's rule entails direct regulation of the retail market - a matter exclusively within state control - it exceeds the commission's authority."</p>
<p>But as to all this, at least from an economic viewpoint, while waiting for the law to catch up with reality I say in all candor that the court has got it completely wrong.</p>
<h4><b>No Longer 'Neat and Tidy'</b></h4>
<p>Back when I was in law school, so many years ago that I can hardly remember the time, my professors (the best ones, at least) would tell me always to read the dissenting opinion. That, they said, was where you would learn the ideas that were worth holding on to. And this case is one that proves the rule.</p>
<p>But first, let me explain what the court's ruling in <i>EPSA v FERC</i> did and did not say.</p>
<p>It did not, in any way shape or form, settle the long-running squabble over which is better: Full LMP, or LMP minus G. The Electric Power Supply Association and many others had advocated LMP minus G. They had argued that consumers who sell demand response back to the wholesale market are not selling energy, per se, but only a call option - the option to buy as much power at retail that they wish, which is guaranteed to them by the retail utility's "obligation to serve." Importantly, they said, a consumer selling DR back to the market did not have to buy fuel or otherwise incur an operating cost in order to produce the asset (the call option, or the foregone consumption) being sold back to the market. Thus, to put sellers of demand response on the same exact footing as power producers, the reward paid to DR should be reduced by the production cost of generation or, in this case, the energy cost portion of the consumer's retail bill, or the value that came to be known simply as "G."</p>
<p>In fact, EPSA and the petitioners challenging FERC Order 745 likely would have been made deliriously happy if the court had stopped half-way and ruled only that full LMP represents overcompensation to demand response and thus discriminates against power plant operators - that FERC has jurisdiction to set a payment for DR sold back into wholesale markets, but in so doing, must get the price right.</p>
<p>Yet the court did not stop there. Rather, it proceeded to try to answer the metaphysical question of whether a kilowatt-hour of retail energy consumption retains its retail character when it becomes aggregated with thousands and millions of other kWhs to become a block of megawatts that is then instrumental in balancing supply and demand at a regional wholesale level. And do we even need to know that answer? For statutory interpretation, perhaps yes, we still do. But here in the 21st century, in an economic sense, in the age of rooftop solar, where consumers act also as producers - there is no longer any real boundary between retail and solar.</p>
<p><b>Several years ago, in the pages of <i>Fortnightly</i></b>, I wrote a column entitled, "<a href="http://www.fortnightly.com/fortnightly/2010/10/one-if-wholesale-two-if-retail" target="_blank">One if by Wholesale, Two if By Retail</a>," <i>(Commission Watch, October 2010, p. 22),</i> describing a policy disagreement between FERC's then-chairman, Jon Wellinghoff, and Commissioner Philip Moeller, over the best way to foster smart grid technology. Wellinghoff had favored a wholesale strategy, focusing on FERC-regulated incentive payments for DR sold into wholesale markets. Moeller, however, had touted a retail focus, aiming to build the smart grid from the bottom up, based on retail programs for price-responsive demand, initiated at the state level. But events have proceeded apace. According to a recent blog post posted by the Pew Charitable Trusts, a new solar power system is now being installed somewhere in the U.S. every four minutes. <i>(See, States Brace for Utilties, Solar Advocates Clash, by Pamela M. Prah.)</i></p>
<p>In <i>EPSA v. FERC</i>, the majority opinion refuses to imagine consumers as wholesale players: "A buyer is a buyer, but a reduction in consumption cannot be a 'wholesale sale.' FERC's metaphysical distinction between price-responsive demand and incentive-based demand cannot solve its jurisdictional quandary."</p>
<p>But Judge Edwards, voting in the minority, thought differently. His dissenting opinion notes that while the petitions challenging FERC's order called on the court to parse the jurisdictional line between FERC's wholesale jurisdiction and state-regulated retail, this line is one "which this court and the Supreme Court have recognized is neither neat nor tidy."</p>
<p>As Edwards saw it, there was no statutory or other compelling reason to include aggregated wholesale demand response within the category of a "sale" of energy. "It is reasonable," he wrote, "to categorize demand response as neither a retail sale nor wholesale sale under the Federal Power Act." Rather, in his view, aggregated wholesale DR takes on the attribute of a physical tool (the most economic one at that) for balancing of supply and demand on a macro level in order to keep rates just and reasonable. It's a tool sorely needed, given the inability, using present technology, to store or stockpile electric energy in any sort of economic manner.</p>
<p>The majority counters that you can't let FERC regulate any and everything that might "affect" wholesale power rates; that rationale, the court says, "has no limiting principle." Otherwise, the court continues, FERC could regulate "any number of areas, including steel, fuel, and labor markets."</p>
<p>But if demand response is inherently retail, then why don't we take the surplus energy that homeowners with rooftop solar are able to sell back to the grid for resale, and treat that as inherently wholesale? In that way, FERC would lose regulatory authority over demand response, but would be repaid in kind by new jurisdiction over net metering.</p>
<p>There's a limiting principle for you. </p>
</div></div></div><div class="field field-name-field-article-category field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Category (Actual): </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/article-categories/ferc">FERC</a></li><li class="taxonomy-term-reference-1"><a href="/article-categories/energy-policy-legislation">Energy Policy &amp; Legislation</a></li></ul></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-department field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Department: </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/department/frontlines">Frontlines</a></li></ul></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1406-FR.jpg" width="708" height="440" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
<div class="field-label">Tags:&nbsp;</div>
<div class="field-items">
<a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/order-745">Order 745</a><span class="pur_comma">, </span><a href="/tags/demand-response">Demand response</a><span class="pur_comma">, </span><a href="/tags/locational-marginal-price">Locational marginal price</a><span class="pur_comma">, </span><a href="/tags/lmp">LMP</a><span class="pur_comma">, </span><a href="/tags/dr">DR</a><span class="pur_comma">, </span><a href="/tags/epact">EPAct</a><span class="pur_comma">, </span><a href="/tags/epsa">EPSA</a><span class="pur_comma">, </span><a href="/tags/electric-power-supply-association">Electric Power Supply Association</a><span class="pur_comma">, </span><a href="/tags/wholesale">Wholesale</a><span class="pur_comma">, </span><a href="/tags/call-option">call option</a><span class="pur_comma">, </span><a href="/tags/overcompensation">overcompensation</a><span class="pur_comma">, </span><a href="/tags/kilowatt-hour">kilowatt-hour</a><span class="pur_comma">, </span><a href="/tags/kwh">kWh</a><span class="pur_comma">, </span><a href="/tags/jon-wellinghoff-0">Jon Wellinghoff</a><span class="pur_comma">, </span><a href="/tags/philip-moeller">Philip Moeller</a><span class="pur_comma">, </span><a href="/tags/smart-grid">Smart grid</a><span class="pur_comma">, </span><a href="/tags/pew-charitable-trust">Pew Charitable Trust</a><span class="pur_comma">, </span><a href="/tags/solar">Solar</a><span class="pur_comma">, </span><a href="/tags/edwards">Edwards</a><span class="pur_comma">, </span><a href="/tags/federal-power-act">Federal Power Act</a><span class="pur_comma">, </span><a href="/tags/net-metering">Net metering</a> </div>
</div>
Wed, 28 May 2014 16:23:03 +0000meacott17212 at http://www.fortnightly.comCongestion on Trialhttp://www.fortnightly.com/fortnightly/2013/05/congestion-trial
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>PJM and the crisis over FTR underfunding.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Bruce W. Radford</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Bruce W. Radford</b> is publisher of <i>Public Utilities Fortnightly</i>. Contact him at <a href="mailto:radford@pur.com">radford@pur.com</a>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - May 2013</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1305-CW-fig1.jpg" width="1350" height="943" alt="Figure 1 - A Growing Funding Shortfall" title="Figure 1 - A Growing Funding Shortfall" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/1305-CW-fig2.jpg" width="938" height="445" alt="Figure 2 - A Simple Grid" title="Figure 2 - A Simple Grid" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>PJM’s latest crisis—the underfunding of financial transmission rights that we’ve seen over the last few years—pushes regulators right to the edge. How far do they trust wholesale power markets? Do they accept the idea, proven by a famous economist, that freely traded financial instruments can work just as well—better even—than firm, physical contract rights?</p>
<p>In PJM’s case, we are told, the problem occurs when too much negative congestion shows up in real-time balancing. But if congestion is bad, shouldn’t negative congestion be good?</p>
<p>Some lay blame on what they say was likely an oversight—an error that PJM made back in June 2000 when it reconfigured its energy market to adopt a twin settlement system, by adding a day-ahead market as a second market clearing interval, in addition to real-time balancing, but somehow forgot at the same time to correct its FTR funding formula to mesh with the new regime.</p>
<p>Whatever the story, the problem seems first to have emerged in earnest about three years ago, according to testimony given by Brian Farley, director of wholesale transactions for FirstEnergy Solutions, which recently filed a complaint seeking redress at the Federal Energy Regulatory Commission. </p>
<p>It was March 2010, as Farley recounts, when FTR payout ratios in PJM first began to turn south, in a trend that has only grown worse with each passing year. For the 2010 and ’11 planning period—running June 1 through May 31—the FTR payout ratio was only 85 percent, producing a revenue inadequacy for PJM market participants of some $254 million. For 2011-’12, the ratio was even worse, at 81 percent. And for the first seven months of the current planning period, 2012-’13, the payout ratio had fallen to an anemic 76 percent.</p>
<p>All told, the FirstEnergy complainants say they have lost nearly $55 million in revenue owned to them as a holder of FTRs acquired to hedge congestion costs: $45.9 million from the funding shortfall, and $9.1 million via an FTR uplift charge—none of which, they say, stems from costs “caused” by their actions, or “from any speculative energy trading activity.”</p>
<p>They ask FERC to rule that PJM’s formula for funding FTRs is no longer just and reasonable. <i>(See, Complaint of FirstEnergy Cos., FERC Dkt. EL13-47, filed Feb. 14, 2013.)</i></p>
<p>Alert to the trend, PJM’s Market Implementation Committee had voted in March 2011 to create a task force to investigate the problem and recommend a fix. Since then, as Farley notes, the FTR task force (FTR-TF) has met numerous times, proposing all manner of solutions, as reported in a 50-page white paper released a year ago. <i>(See, “</i><a href="http://www.pjm.com/~/media/documents/reports/20120430-ftr-revenue-stakeholder-report.ashx" target="_blank"><i>FTR Revenue Stakeholder Report</i></a><i>,” Apr. 30, 2012, available on the PJM web site.) </i></p>
<p>By all accounts, PJM stakeholders have been debating the FTR underfunding issue now for about 30 months, but to no avail. PJM itself has acknowledged the stalemate:</p>
<p>“Suffice it to note,” as PJM wrote in its answer to FirstEnergy, filed March 17 of this year, “that the membership, as a collective, is hopelessly divided and unable to move forward with any reform in an area where a majority regards even the status quo as undesirable.”</p>
<h4>Symptoms and Causes</h4>
<p><span class="s3">On the surface, FTR underfunding stems from a mismatch in the PJM tariffs.</span></p>
<p>This mismatch occurs between how PJM defines the payout obligations owed to FTR holders, versus the way PJM defines the sources of revenues to be collected to pay off those FTR obligations. The obligations are fixed solely in terms of day-ahead congestion, that being the nodal differentials in day-ahead locational marginal energy prices, or LMP. By contrast, the source of funding those FTR obligations comes from both day-ahead and real-time balancing congestion—of which the latter increasingly turns out to be negative. Of all the regional grids with organized power markets, only ISO-NE does it this way. And New England reportedly copied this element of its tariff directly from PJM.</p>
<p>When FERC first approved PJM’s move to an LMP-based energy market, with FTRs to create a new type of financially firm transmission service to replace physical rights and allow traders to “buy through” the congestion, that approval was founded in part on Harvard Prof. Bill Hogan’s novel theorem.</p>
<p>And that theory states that any given array of FTRs plotted over a particular set of transmission paths, and then allocated or sold to regional market participants, will be revenue-adequate if 1) the grid operator can confirm beforehand that the FTRs as a group are simultaneously feasible, and 2) if the grid topology or configuration is the same for both a) the original issuance of FTRs, and b) the security-constrained, bid-based economic dispatch that clears the market and sets the LMPs, which in turn define the payoff for those FTRs.</p>
<p>In such a case, as Hogan explained in a paper he submitted to the FERC record in the FirstEnergy FTR underfunding complaint, “then no matter what the pattern of actual loads and generation, [an] economic dispatch with locational prices would be revenue-adequate.” <i>(See, Hogan, “Financial Trans. Rights, Revenue Adequacy and Multi-Settlement Electricity Markets,” p. 2, in Attachment A with comments of the Financial Institutions Energy Group, FERC Dkt. EL13-47, filed Mar. 18, 2013.)</i></p>
<p>Others, however, such New Jersey Attorney General Jeffrey Chiesa, who opposes the FirstEnergy complaint on behalf of his state Board of Public Utilities, remain unimpressed with such theories.</p>
<p>As Chiesa argues, the increased negative real-time balancing congestion that has put FTR funding underwater is only a symptom. The real source of FTR underfunding, he posits, are the more profound causes identified in PJM’s April 2012 stakeholder report on FTR underfunding.</p>
<p>That report noted a handful of true causes, most of which concern a “less-tight” seam around the PJM footprint, creating problematic transactions on borders and interfaces with the Midwest ISO and other external balancing areas—all of which make it difficult for PJM to accurately predict day-ahead market conditions, which in turn exposes PJM to eventual balancing corrections that increasingly create negative congestion (<i>i.e.,</i> real-time congestion that fails to generate revenue for PJM to use in paying off FTRs).</p>
<p>Among these identified causes:</p>
<ul>
<li>Many more market-to-market flowgates, especially with MISO;</li>
<li>Intermittent resources (read “wind”) suddenly showing up at the PJM border in real time (wind generally doesn’t offer day-ahead); and</li>
<li>An increasing lack of coordination of transmission outage planning across seams.</li>
</ul>
<p>And the shale-gas revolution and shutdown of aging coal plants might be playing a role as well. For example, PJM reports “reduced internal PJM west-to-east flows due to a relative increase in coal resource offer prices in the western part of the PJM region and a relative reduction in gas-fired resource offer prices in the eastern part.”</p>
<p>The April 2012 report also notes that 188 new market-to-market flowgates were added to the PJM-MISO coordination process during the prior two years, 150 of them at MISO’s request. Consultant Roy Shanker testified on this last point in his affidavit filed on behalf of DC Energy and Vitol:</p>
<p>“There is nothing wrong per se with creating new flow gates… If PJM knew about these new flowgate constraints … the constraint would be part of the model and less rights would be feasible and less rights awarded. The problem occurs because the Joint Operating Agreement [with MISO] allows for these elections of new flowgates in between annual FTR auctions. When this occurs, rights that previously had been feasible may become infeasible, and underfunding will occur.” <i>(Prepared direct testimony of Roy Shanker, p. 21, filed Mar. 18, 2013.)</i></p>
<p>To provide perspective, Exelon explains why all these factors, taken together, can lead to underfunded FTRs:</p>
<p>“The common thread among these causal factors is that PJM cannot accurately predict and reflect such occurrences in its day-ahead market model. When such conditions occur, the day-ahead market and the real-time market topology deviate, often resulting in transmission constraints that increase real-time congestion costs.” </p>
<p>And DC Energy General Counsel Joelle K. Ogg and Vitol Legal Compliance Director Robert Viola offer a telling observation:</p>
<p>“As PJM grew geographically—both via geographic expansion and joint coordination along an increasingly large set of seams—so too did the magnitude of negative balancing congestion.” <i>(See, Comments of DC Energy LLC and Vitol, Inc., p. 9, FERC Dkt. EL13-47, filed Mar. 18, 2013.)</i></p>
<p>Overall, PJM was quite candid in its answer filed at FERC, agreeing with much of what was documented in the FirstEnergy complaint:</p>
<p>“While negative balancing congestion is common because transmission system capability in the real-time energy market is generally the same or lower than … day-ahead … the growing trend of increasing negative balancing congestion is alarming.”</p>
<h4>Searching for Solutions</h4>
<p>In their complaint, the FirstEnergy companies propose to exclude real-time balancing congestion from the FTR funding calculus, so that FTR revenue adequacy is dependent only on congestion in the day-ahead market—a solution that even PJM says it would support.</p>
<p>And this proposed change, as noted by Edison Mission Marketing &amp; Trading, in its comments filed at FERC, would make PJM’s FTR calculations consistent with those of MISO and the New York and California ISO.</p>
<p>Robert Stoddard, a vice president at Charles River Associates (CRA), provides a bit more detail in his affidavit:</p>
<p>“Of the four other such RTOs with a two-settlement system, only ISO New England also pools the day-ahead and balancing market congestion credits to fund FTRs and allows the potential for systematic underfunding …</p>
<p>“The other three RTOs [CAISO, MISO, and NYISO] either fund FTR solely from day-ahead congestion receipts, and/or guarantee full payment.”</p>
<p>The difficult question, however, is what to do with the cost of the negative real-time balancing congestion, if it’s no longer netted against positive day-ahead congestion receipts. That’s where the real argument lies.</p>
<p>FirstEnergy proposes that FERC should order PJM to allocate the leftover real-time balancing congestion costs <i>pro rata</i> to all transmission users, as a class, since it’s impossible to identify any particular market participant or group of participants as responsible for causing these expenses. </p>
<p>State regulators from Maryland, New Jersey, Indiana, Ohio, and Pennsylvania oppose that idea, complaining that it would force balancing congestion costs largely on retail ratepayers, while letting many FTR holders go free—to the extent that they might use their financial hedging rights only to back up virtual trades, to avoid falling within any defined class of grid “users.”</p>
<p>Listen to Maryland PSC general counsel H. Robert Erwin, Jr., commenting on behalf of his state commission:</p>
<p>“The Maryland PSC strongly opposes this request, which could impose a $25 million or greater annual cost increase upon Maryland electricity end users and a $250 million or greater cost increase upon PJM-wide transmission end users.” <i>(Comments, p. 3, FERC Dkt. EL13-47, filed Mar. 18, 2013.)</i></p>
<p>A protest filed by the PJM Industrial Customer Coalition, plus three rural co-ops from North Carolina, Maryland, and Virginia, puts it a little more bluntly:</p>
<p>“FirstEnergy’s proposed solution is reactionary and heavy handed.”</p>
<p>In fact, many of the commenting state regulators seem to hold the opinion that FTRs are designed only for rank speculation, so that the holders ought to be prepared to bear the risk that funding for FTR payouts might fall short.</p>
<p>Maryland’s Erwin is one who gives voice to this notion, arguing that if FERC should approve FirstEnergy’s proposal to force significant uplift charges on end users to cover negative balancing congestion no longer allocated to FTR holders, then “it is necessary that this commission [FERC] require a demonstration from PJM and/or transmission owners that these additional FTRs are indeed stimulating valuable, beneficial market activity.”</p>
<p>Commenting on behalf of the New Jersey Board, Chiesa adds:</p>
<p>“FTRs are no longer representative of the costs associated with [the] LSEs’ historic investment in transmission, but rather a speculative financial hedge …</p>
<p>“Like any speculative investment, there is also no guarantee that FTR transactions will result in profit.”</p>
<p>Monitoring Analytics, the PJM Independent Market Monitor, led by its President and General Counsel Joseph Bowring and Jeffrey Mayes, picks up on this thread.</p>
<p>The IMM points out that PJM changed policy in 2003, ending the practice of allocating FTRs directly to load-serving utilities, and instead began its current plan of furnishing utilities only with ARRs—auction revenue rights, which entitle the holder to receive the revenue stream from auction sales of the actual FTRs. This change, the IMM argues, means that if there’s to be any sort of regulatory compact to ensure that congestion rights are adequately funded, it should extend only to ARRs, which serve as a <i>quid pro quo</i> substitute for the physical grid rights that utilities willingly gave up for PJM’s market vision. Such protection shouldn’t extend to FTRs, according to the market monitor, as they no longer serve the public interest, but only aid in financial speculation:</p>
<p>“ARRs [now] are directly allocated to loads in recognition of the fact that loads pay for the transmission system,” the monitor writes.</p>
<p>“PJM created the split between ARRs and FTRs … to provide the appropriate protection against congestion for load [via ARRs] … and to permit … those market participants who wished to use FTRs to speculate.”</p>
<p>This notion, that ARRs are somehow good, and FTRs bad, strikes CRA’s Stoddard as nonsensical:</p>
<p>“I strongly disagree with the Market Monitor’s unsupported assertion…</p>
<p>“The value of ARRs is dependent on the value of FTRs. In the extreme case, if market participants expected FTRs to be completely unfunded, they would be unwilling to pay anything for FTRs and, in turn, ARR holders would receive no auction revenues.”</p>
<p>PJM counsel Jeanine Watson seems to agree:</p>
<p>“Reduced prices for FTRs leads to less money to fund ARRs.</p>
<p>“ARRs are held by the load-serving entities, so, in the end, it is the load-serving entities that will be ultimately impacted by the reduced FTR revenues—one way or another.”</p>
<h4>Going Granular</h4>
<p>While PJM confirms that it “generally supports” the FirstEnergy proposal to remove the often-negative real-time congestion from FTR funding, and to reallocate that congestion, “whether negative or positive,” to all grid customers, it believes that this reallocation “would be improved” by defining “grid customers” as broadly as possible.</p>
<p>And that might help bring the doubting state PUCs on board.</p>
<p>In this case, PJM recommends that FERC should take the FirstEnergy complaint proposal and expand it so that the real-time congestion charges—the costs and revenues—are allocated not only to all physical grid injections and withdrawals of actual megawatt-hours, but also to virtual supply and demand deviations, plus an obscure category of transactions known in the trade as “up-to congestion,” which operate as pseudo-FTRs that can hedge congestion in the real-time market.</p>
<p>Presumably, PUCs and load-serving utilities would welcome this offer to hit virtual traders, often seen as financial speculators, just as hard or harder than retail ratepayers. Yet, as might be expected, this counterproposal has prompted a backlash from the financial community.</p>
<p>An ad-hoc group of financial marketers—Cobalt Capital Partners, Twin Cities Power Holdings, Red Wolf Energy Trading, and XO Energy—claim that virtual trading produces real value by fostering price convergence between day-ahead and real-time energy markets. They also cite analysis from Prof. Hogan that trying to push such costs onto purely financial transactions will backfire, since virtual traders will just take their money and go somewhere else:</p>
<p>“By contrast,” Hogan writes, “real load, in real time, has nowhere to go. Financial participants have many more options.”</p>
<p>Independent consultant Roy Shanker offers another way forward. He recommends breaking up PJM’s model of yearly FTR planning into smaller, more granular bites.</p>
<p>At present, PJM conducts its simultaneous feasibility test for allocating ARRs and auctioning off FTRs only once each year, for each separate planning period, making assumptions about grid outages, facility ratings, loop flows, interface ratings, and the like, before estimating the maximum allowable quantity of ARRs and FTRs. As PJM explains, this SFT process “spans approximately five months,” starting in mid-January and ending on May 31, the day before the start of the next planning year. <i>(Answer of PJM, p. 16, FERC Dkt. EL13-47, filed March 17, 2013.)</i></p>
<p>Yet, as Shanker points out, while grid capacity and configuration are constantly changing, the FTRs approved for auction through this annual SFT process are expected to remain viable across the entire planning year. Thus, Shanker suggests conducting the SFT analysis and ARR-FTR process much more frequently, such as seasonally or even monthly: “This would allow for much more granular resolution of changes in system topology.” <i>(See, Shanker, Direct Testimony, p. 7, FERC Dkt. EL13-47, filed March 18, 2013.)</i></p>
<p>As Shanker explains, PJM currently will exclude a transmission element from its assumptions about grid facility capacity if a planned outage on that line is to last longer than two months:</p>
<p>“So a number of seven-week outages could exist,” he notes, “and the annual model would allow rights to be awarded as if the lines were in service all 52 weeks of the year.</p>
<p>“The annual process,” Shanker adds, “has no seasonal representations, and thus ‘misses’ material outages, resulting in the award of rights for transmission that does not exist.”</p>
</div></div></div><div class="field-collection-container clearfix"><div class="field field-name-field-sidebar field-type-field-collection field-label-above"><div class="field-label">Sidebar:&nbsp;</div><div class="field-items"><div class="field-item even"><div class="field-collection-view clearfix view-mode-full field-collection-view-final"><div class="entity entity-field-collection-item field-collection-item-field-sidebar clearfix">
<div class="content">
<div class="field field-name-field-sidebar-title field-type-text field-label-above"><div class="field-label">Sidebar Title:&nbsp;</div><div class="field-items"><div class="field-item even">Understanding Negative Congestion: How FTRs become underfunded in real time</div></div></div><div class="field field-name-field-sidebar-body field-type-text-long field-label-above"><div class="field-label">Sidebar Body:&nbsp;</div><div class="field-items"><div class="field-item even"><!--smart_paging_autop_filter--><!--smart_paging_filter-->Negative congestion can arise during the real-time or balancing settlement, in a twin-settlement market like PJM—with separate day-ahead, and real-time market-clearing intervals. Robert Stoddard, a vice president at Charles River Associates, explains this phenomenon in his filings in support of the recent complaint filed by FirstEnergy, asking the Federal Energy Regulatory Commission (FERC) to resolve the problem of FTR underfunding in PJM. (See, FERC Dkt. EL13-47, filed Feb. 15, 2013.)
Figure 2 is taken from the three Stoddard Exhibits, RBS-2 through RBS-4.
Assumptions: Assume a simple electric grid with two nodes, A and B, with generating plants located at each node (Gen A at node A, Gens B1 and B2 at node B), a utility load of 500 MW at node B (LSE B), and a maximum grid transfer capability from A to B of 500 MW. The respective maximum outputs and marginal running costs for the three generating plants are given in the diagram.
Base Case: Day-Ahead Clearing Only: In the DA least-cost dispatch, Utility B’s 500-MW load is served 300 MW by Gen A, 180 MW by Gen B1, and 20 MW by Gen B2. The LMPs at the two nodes are $30 (A) and $42 (B). Total DA congestion = $3,600 (the difference between what load pays at Node B ($21,000 = 500 MW x $42), and the sum of what the Gens receive in total energy sales revenues ($17,400) at both A ($9,000 = 300 MW x $30) and B ($7,560 = 180 MW x $42). This figure ($3,600) is also the total funding available to be paid to FTR holders. FTRs are 100-percent funded.
Case 1: Load = 450 MW(DA); 500 MW(RT): This case creates an FTR funding surplus of $360, even though there’s no DA congestion, as the LMPs at A and B are both $30, because the smaller 450-MW DA load can be served entirely by the two lowest cost plants, Gen A and Gen B1. The $360 surplus stems entirely from RT balancing congestion. DA Load pays $13,500 (450 MW x $30), the same as $13,500 in total DA revenues paid to Gen A ($8,100 = 270 MW x $30) plus B1 ($5,400 = 180 MW x $30). But in the RT re-dispatch, in order to serve the extra 50 MW of load, output must increase at Gens A (30 MW) and B1 (20 MW), at a total cost of $1,740: $900 for Gen A (30 MW x $30) and $840 for Gen B1 (20 MW x $42). Load must pay an extra $2,100 for this RT re-dispatch (40 MW x $42). The difference of $360 ($2,100 minus $1,740) is the FTR funding surplus.
Case 2: RT Forced Transmission Outage: In this case, DA conditions are the same as in the base case, producing $3,600 in congestion and FTR obligations, but the transmission link between Nodes A &amp; B goes down completely in real time. This outage will create negative RT balancing congestion of $3,600. That’s because in the RT re-dispatch, load must now pay an extra congestion charge of $3,600, but the PJM RTO can’t collect those revenues; they go instead to Gens B1 and B2, as part of the higher LMP energy sales price at Node B, due to the transmission outage. Load will now pay an additional $3,600. Load avoids the $9,000 payment to buy 300 MW from Gen A at a price of $30, but now incurs an extra payment of $12,600 to replace that 300 MW by buying from Gen B2 at $42. At the same time, Gens B1 (180 MW) and B2 (320 MW) sell more power collectively, but because they sell at Node B, with a higher LMP of $42, they pocket the entire $21,000. Gen B1 gets $7,560 (180 MW x $42), and B2 gets $13,440 (320 MW x $42). The RT redispatch adds $3,600 in congestion, but it’s negative congestion, as PJM earns no compensation with which to fund payments to FTR holders.—BWR</div></div></div> </div>
</div>
</div></div></div></div></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-department field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Department: </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/department/commission-watch">Commission Watch</a></li></ul></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1305-CW.jpg" width="800" height="531" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
<div class="field-label">Tags:&nbsp;</div>
<div class="field-items">
<a href="/tags/pjm">PJM</a><span class="pur_comma">, </span><a href="/tags/ftr">FTR</a><span class="pur_comma">, </span><a href="/tags/financial-transmission-rights">financial transmission rights</a><span class="pur_comma">, </span><a href="/tags/day-ahead">day-ahead</a><span class="pur_comma">, </span><a href="/tags/brian-farley">Brian Farley</a><span class="pur_comma">, </span><a href="/tags/firstenergy-solutions">FirstEnergy Solutions</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/ftr-tf">FTR-TF</a><span class="pur_comma">, </span><a href="/tags/locational-marginal-price">Locational marginal price</a><span class="pur_comma">, </span><a href="/tags/lmp">LMP</a><span class="pur_comma">, </span><a href="/tags/iso-ne">ISO-NE</a><span class="pur_comma">, </span><a href="/tags/bill-hogan">Bill Hogan</a><span class="pur_comma">, </span><a href="/tags/jeffrey-chiesa">Jeffrey Chiesa</a><span class="pur_comma">, </span><a href="/tags/midwest-iso">Midwest ISO</a><span class="pur_comma">, </span><a href="/tags/miso">MISO</a><span class="pur_comma">, </span><a href="/tags/wind">Wind</a><span class="pur_comma">, </span><a href="/tags/shale-gas">Shale gas</a><span class="pur_comma">, </span><a href="/tags/coal">coal</a><span class="pur_comma">, </span><a href="/tags/roy-shanker">Roy Shanker</a><span class="pur_comma">, </span><a href="/tags/exelon">Exelon</a><span class="pur_comma">, </span><a href="/tags/dc-energy">DC Energy</a><span class="pur_comma">, </span><a href="/tags/joelle-k-ogg">Joelle K. Ogg</a><span class="pur_comma">, </span><a href="/tags/vitol">Vitol</a><span class="pur_comma">, </span><a href="/tags/robert-viola">Robert Viola</a><span class="pur_comma">, </span><a href="/tags/edison-mission-energy">Edison Mission Energy</a><span class="pur_comma">, </span><a href="/tags/robert-stoddard">Robert Stoddard</a><span class="pur_comma">, </span><a href="/tags/charles-river-associates">Charles River Associates</a><span class="pur_comma">, </span><a href="/tags/cra">CRA</a><span class="pur_comma">, </span><a href="/tags/rto">RTO</a><span class="pur_comma">, </span><a href="/tags/caiso">CAISO</a><span class="pur_comma">, </span><a href="/tags/nyiso">NYISO</a><span class="pur_comma">, </span><a href="/tags/h-robert-erwin">H. Robert Erwin</a><span class="pur_comma">, </span><a href="/tags/monitoring-analytics">Monitoring Analytics</a><span class="pur_comma">, </span><a href="/tags/joseph-bowring">Joseph Bowring</a><span class="pur_comma">, </span><a href="/tags/jeffrey-mayes">Jeffrey Mayes</a><span class="pur_comma">, </span><a href="/tags/auction-revenue-rights">auction revenue rights</a><span class="pur_comma">, </span><a href="/tags/arr">ARR</a><span class="pur_comma">, </span><a href="/tags/jeanine-watson">Jeanine Watson</a><span class="pur_comma">, </span><a href="/tags/cobalt-capital">Cobalt Capital</a><span class="pur_comma">, </span><a href="/tags/twin-cities">Twin Cities</a><span class="pur_comma">, </span><a href="/tags/red-wolf">Red Wolf</a><span class="pur_comma">, </span><a href="/tags/xo-energy">XO Energy</a> </div>
</div>
Fri, 03 May 2013 04:17:29 +0000meacott16568 at http://www.fortnightly.comTrading on a Knife Edgehttp://www.fortnightly.com/fortnightly/2012/12/trading-knife-edge
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>The Deutsche Bank case and the meaning of ‘price manipulation.’</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Bruce W. Radford</p>
</div></div></div><div class="field field-name-field-import-category field-type-text field-label-inline clearfix"><div class="field-label">Category:&nbsp;</div><div class="field-items"><div class="field-item even">Commission Watch</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Bruce W. Radford</b> is publisher of <i>Public Utilities Fortnightly</i>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - December 2012</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1212-CW-fig1a.jpg" width="676" height="816" alt="In referring the Deutsche Bank matter to FERC for possible enforcement action, the California ISO’s department of market monitoring found that DBET traders had established a pattern of circular trading, by purchasing power exports out of CAISO at the Silver Peak intertie node, moving them across Sierra Pacific Power transmission to the Summit node (the E-Tag dotted line), and re-importing the same power back into CAISO, to be wheeled back to the starting point, in a manner “inconsistent with ISO and FERC ma" title="Figure 1 - Improper Wheel-Through? In referring the Deutsche Bank matter to FERC for possible enforcement action, the California ISO’s department of market monitoring found that DBET traders had established a pattern of circular trading, by purchasing power exports out of CAISO at the Silver Peak intertie node, moving them across Sierra Pacific Power transmission to the Summit node (the E-Tag dotted line), and re-importing the same power back into CAISO, to be wheeled back to the starting point, in a manner “inconsistent with ISO and FERC market rules.” However, the Deutsche Bank defense team claims that no circular trading occurred, as evidenced by the lack of E-Tags for any alleged wheeling within CAISO from Summit to Silver Peak. Source: DBET Exhibit L, p. 13, FERC Dkt. IN12-4, filed Nov. 5, 2012. " /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/1212-CW-fig2a.jpg" width="1366" height="964" alt="This figure depicts a hypothetical combination of supply and demand bids that could’ve created a situation of “degeneracy” at the Silver Peak intertie node, by which the market-efficient, security-constrained, least-cost dispatch solution under the California ISO market tariff could’ve indicated not a single, unique market-clearing locational marginal price (LMP), but a range of prices, falling between the lowest-priced supply bid (import bid) and the highest-priced demand bid (export bid)—any one of which " title="Figure 2 - Degenerate Pricing - This figure depicts a hypothetical combination of supply and demand bids that could’ve created a situation of “degeneracy” at the Silver Peak intertie node, by which the market-efficient, security-constrained, least-cost dispatch solution under the California ISO market tariff could’ve indicated not a single, unique market-clearing locational marginal price (LMP), but a range of prices, falling between the lowest-priced supply bid (import bid) and the highest-priced demand bid (export bid)—any one of which would be viewed by the ISO software as a “correct” price. The Deutsche Bank defense team argues that the California ISO’s market software improperly selected a default price from within the degenerate range that violated the ISO’s tariff, which defines the LMP price as the value of serving the next increment of demand." /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>A few months back, the Federal Energy Regulatory Commission directed Deutsche Bank Energy Trading LLC to show cause why it shouldn’t be assessed a civil penalty of $1.5 million and be made to return some $123,000 in allegedly unjust profits from power trading in markets run by the California ISO.</p>
<p>FERC acted on an investigation and proposed findings reported by its internal Office of Enforcement. That investigation had found evidence that Deutsche Bank engaged in a “fraudulent scheme” of trading in one market to benefit a position in another, aided by “falsely designating” certain imports and exports as complying with ISO rules.</p>
<p>Moreover, FERC’s enforcement staff alleged that Deutsche Bank had “conceived and executed” a program of trading in spot energy markets, from January through March 2010, so as to benefit certain complementary positions that Deutsche Bank had held on CRRs—“congestion revenue rights,” the term used by the ISO in California to describe what are more commonly known, in East Coast markets, as FTRs, or “financial transmission rights.” <i>(See, Order to Show Cause and Notice of Proposed Penalty, Dkt. IN12-4, Sept. 5, 2012, 140 FERC ¶61,178.) </i></p>
<p>In purely dollar terms, the Deutsche Bank case falls short of some other recent enforcement actions. It was only this past March that FERC exacted a $245 million settlement from Constellation Energy Commodities Group—the largest ever ordered by the commission, including penalty and disgorged profits.</p>
<p>Yet this comparison wasn’t lost on John Estes and the rest of Deutsche Bank’s legal defense team from Skadden, Arps, Slate, Meagher &amp; Flom. Their response to the charges from the FERC staff, filed early last month, acknowledges the small sums involved:</p>
<p>“Given that Enforcement seeks sanctions here of only $1.6 million—a small amount compared to other alleged energy manipulation cases—one might wonder,” the defense writes, “why DBET has not already settled.”</p>
<p>“After all, the cost of defending the case is likely to exceed the amount Enforcement seeks.”</p>
<p>Yet the stakes couldn’t be higher. And the reason, says the Deutsche Bank defense team, comes down to a “point of principle.”</p>
<p>Recall that in the Constellation settlement, enforcement staff had found CECG culpable of trading in one set of markets (virtual and day-ahead physical schedules) with the aim of maximizing returns in others (financial positions on contracts for differences). And now, in the Deutsche Bank matter, staff advances a similar-sounding charge: that Deutsche Bank “falsely scheduled unprofitable physical exports at the Silver Peak intertie with the intent to benefit its financial positions [on congestion rights] in the ISO system. <i>(See, 2012 Report on Enforcement, FERC Office of Enforcement, Dkt. AD07-13-005, Nov. 15, 2012, p. 7.) </i></p>
<p>But at the same time, the legal defense team from Skadden Arps appears to have made at least a <i>prima facie</i> case that Deutsche Bank’s scheduling of physical transactions wasn’t false or misleading, nor intentionally unprofitable. If this defense should hold up—that Deutsche Bank traded honestly, openly, and efficiently (with a profit-seeking intent)—then FERC’s case will be left resting solely on the notion that market manipulation can be shown simply through trading in one sphere, such as physical schedules in a spot cash market, while holding a complementary position in another, such as a financial market that trades hedging derivatives.</p>
<p>Deutsche Bank and its Skadden Arps legal team reject that notion as inimical to markets. In fact, they’ve come to see themselves as going to bat for an “entire industry”—as defending the very idea of wholesale power trading, as practices in markets run by FERC-sanctioned (ISO-RTO) regional grid operators:</p>
<p>“The legal position Enforcement has taken here is radical,” writes the Deutsche Bank legal defense team from Skadden Arps. “Essentially,” they assert, “Enforcement’s position is that knowingly trading in two related markets is <i>per se</i> unlawful market manipulation, even if the trading is profit-seeking in both markets.” <i>(See, Answer of DB Energy Trading to Order to Show Cause, Dkt. IN12-4, p. 1, filed Nov. 5, 2012.) </i></p>
<p>And on this point the defense has brought out the big guns. Testifying on behalf of Deutsche Bank, the electric industry expert and Harvard Prof. William Hogan sees the case as a threat against the market regime he helped create and continues to stand for:</p>
<p>“If holding a financial contract that benefits from the price impact of a physical transaction were to be deemed all that is required to establish price manipulation, then the entire foundation of efficient electricity market design would be destroyed with one stroke.” <i>(DBET Exhibit P, Affidavit of William W. Hogan, p. 36.)</i></p>
<p>Also testifying for Deutsche Bank is consultant Roy Shanker, who argues that such a theory, if accepted by FERC, will bring chaos to wholesale power trading:</p>
<p>“How do you make any decisions regarding manipulation,” he asks, “when it is indistinguishable from rational economic behavior.” <i>(DBET Exhibit O, Affidavit of Roy J. Shanker, p. 84.) </i></p>
<p>Are Hogan and Shanker crying wolf?</p>
<p>Well, maybe a little, but now here comes the really interesting part—the real villain in this case might not be the traders, but the software.</p>
<p>It turns out that RTO/ISO markets have a weak spot at thinly traded export nodes that intertie with adjacent non-market areas. A phenomenon known as “degeneracy” can develop, according to Hogan and Shanker, whereby the software algorithm that solves the efficient, least-cost dispatch can’t resolve a single market-clearing locational marginal price (LMP) at the node in question.</p>
<p>Normally the software will first determine a simultaneous clearing of all supply and demand bids to arrive at a single, least-cost dispatch of resources that obeys all security constraints. But then will discover—to the dismay of its silicon brain—that this dispatch occurs not just at a single, unique market price, but can be solved mathematically across a range of multiple alternative LMPs, each of which the software will see as a correct, market-efficient price.</p>
<p>This range of prices can be volatile, according to Hogan and Shanker, leaving traders balanced on a knife-edge. That’s because a single, small incremental bid can instantly collapse the pricing range at such a thinly traded node and produce a new, much higher or lower LMP, putting the trader out of the money.</p>
<p>The defense team argues that this degeneracy phenomenon occurred in the Deutsche Bank case, causing the California ISO software to send potentially misleading signals to Deutsche Bank traders concerning prices and congestion. In fact, the defense team analyzed the prices and congestion that the ISO software posted, with the assistance of the ISO’s Department of Market Monitoring, and drew a remarkable conclusion. The defense found, it claims, that the ISO must have pre-programmed its software with an arbitrary “default” solution. This default, the defense says, would always resolve the price ambiguity by selecting one price out of the degenerate range of all possible correct prices, and posting that one price as the LMP, and thus the indicator of the direction and value of congestion.</p>
<p>Moreover, according to the defense <i>(see DBET Answer, p. 53),</i> this default price violated the ISO’s filed tariff and misled the Deutsche Bank traders:</p>
<p>“Whenever the software selected the low end of the degenerate range, the resulting low price … created an apparent profit opportunity for market participants.”</p>
<h4>Silver Peak to Summit</h4>
<p>To understand what happened, turn to Figure 1. DBET claims its traders sought profits in moving power from the Silver Peak intertie node to Summit, as the historical market data seemed to indicate an average price differential (higher at Summit, lower at Silver) of about $10 to $14/MWh, whereas the necessary transmission service to be obtained from Sierra Pacific Power was thought to cost only about $5 to $6, with CAISO charges running only about $1.50 to $2 to submit export bids at Silver Peak (bidding to buy power exported there from the ISO), and import bids at Summit (to sell back into CAISO).</p>
<p>But as Deutsche traders planned to submit mainly self-scheduled (price-taker) export bids at Silver Peak, they first chose to hedge price risk (the risk that the buy price at Silver Peak might rise too high) by acquiring CRRs at auction that would pay off if congestion appeared in the export direction—<i>i.e., </i>if prices at the Silver Peak intertie exceeded prices inside CAISO.</p>
<p>DBET in fact scheduled and reported these physical transactions, with trading volumes varying from day to day, from January through March 2010, as indicated in Figure 1 by the dotted line labeled “E-Tags.” And as DBET wanted the entire transaction to go forward, without one of either the export or import legs being cut (failing to clear), it lumped the two deals together as a single “wheel-through” transaction under CAISO practice, so if a piece of the transaction didn’t clear, the entire deal would be cut.</p>
<p>In truth, however, the combined deals didn’t qualify under CAISO’s tariff as wheel-throughs, as the ISO tariff reserves that category for transactions that move power across CAISO from one intertie point to another, but with source and sink both occurring outside the ISO. And so because these physical transactions apparently violated CAISO’s tariff, and eventually turned out to be money-losing, FERC’s enforcement staff alleges them to be fraudulent—part of a circular scheme of physical trades devised primarily to capture revenue in a wholly separate financial derivatives market: from the export-direction CRRs held by Deutsche Bank.</p>
<p>And in an interesting twist, Enforcement bolsters its case by pointing out the notable coincidence that the DBET trader assigned initially to acquire a financial interest in ISO congestion rights was allegedly the same person who, in a previously life, wrote the software for the ISO’s CRR market. (DBET claims however, that the trader only created the CRR software interface, not the algorithmic “engine.”)</p>
<p>Yet the evidence also tends to show that the ISO might have wrongly advised DBET and other market participants early on that this combination of export and import trades would indeed qualify as a wheel-through under CAISO practice. As the defense claims, ISO employees seemed not to be familiar with the exact terms of the wheel-through tariff, as the ISO’s Business Practice Manual (since modified) appeared to allow what DBET was doing.</p>
<p>Consider this excerpt <i>(See DBET Exhibit G)</i> from a transcript of a telephone call between the ISO and an unnamed, third-party market participant, from May 2009:</p>
<p><b>Market Participant:</b> Hey. So, I had a question … if I wheel some power, can I export and then import it back in? Or … does the wheel have to go me importing it and then exporting it back out?</p>
<p><b>CAISO:</b> Yeah, you can export it and then import it back out. … we have a lot of that.</p>
<p><b>Market Participant:</b> I’m looking to export at Palo … and then import it back in at Westwing.</p>
<p><b>CAISO:</b> Yeah, I’ve never seen us not allow it.</p>
<p>According to another telephone transcript <i>(DBET Exhibit H, from March 2010),</i> another market participant had asked about how to tag a certain transaction—“when we do a wheel, which is, you know … an import and an export tied together”—and the CAISO employee on the other end had answered, “We’ve done this for a few months now and they’re always approved.”</p>
<p>Yet by June 2010, when the ISO referred the case to FERC enforcement for investigation <i>(DBET Exhibit L, p. 14),</i> the ISO was accusing DBET of circular scheduling, which itself was seen as a fraudulent practice:</p>
<p>“The circular nature of these imports and exports is inconsistent with ISO and FERC market rules prohibiting submission of false information and/or manipulation.”</p>
<p>For its part, Deutsche Bank denies any charge of circular scheduling, pointing out that the E-Tags show only the exports at Silver Peak, the transmission across Sierra Pacific Power to Summit, and the imports at Summit, and arguing that the ISO’s market monitoring department might’ve erroneously inferred the circular schedule from DBET’s apparently improper use of the wheel-through designation. <i>(See DBET Answer, pp. 66-69.) </i></p>
<p>As for whether Deutsche Bank’s physical trades were profit-seeking, the evidence is dramatic. Note first that in June 2010, the ISO’s initial report referring the matter to FERC’s Enforcement Office <i>(DBET Answer, Exhibit L, pp.3, 10)</i> had identified some $42,000 in trading profits. Five months later, however, in November 2010, when the ISO’s market monitoring department sent a follow-up referral letter to FERC, the DMM identified a DBET trading loss of about $6,800. <i>(See DBET Exhibit M, p.7.) </i></p>
<p>As Shanker observes, that late correction came only because it took that long for the ISO to process and issue all pertinent invoices:</p>
<p>“Given the CAISO DMM’s apparent difficulty in determining the profitability … the traders’ misunderstanding is not surprising.”</p>
<h4>Software Going Rogue</h4>
<p>Now consider Figure 2, which is taken from the Hogan affidavit in the Deutsche Bank case.</p>
<p>At a thinly traded intertie like Silver Peak, as depicted in the figure, the supply and demand curves won’t appear as gently sloping continuous lines that intersect, but rather, as discontinuous stair-step functions, as is shown on the right-hand side.</p>
<p>That makes it problematic to calculate the market-clearing price, as the supply and demand curves don’t even meet.</p>
<p>Instead, as Hogan explains in his affidavit, Figure 2 depicts a hypothetical degenerate pricing situation where an LMP price anywhere between $15 and $50 would solve the least-cost dispatch solution, and would serve in theory as an efficient and correct market-clearing price.</p>
<p>The actual situation in the Deutsche Bank was similar, but with slightly different numbers: $70 (rather than $50) for the lowest-cost supply bid (import bid), and $55 (rather than $40) for the market price in CAISO.</p>
<p>Also, in the actual case, the ISO had imposed an import transfer limit at Silver Peak of 0 MW, meaning that no import bid could clear, as no additional imports could be scheduled without exceeding the transfer limit.</p>
<p>These facts would’ve created a degenerate price range of between $15 and $55: any market-clearing price within this range would be “efficient” and would satisfy the unique least-cost, security constrained dispatch solution.</p>
<p>But in this situation, according to the defense, the CAISO software defaulted to $15, the lowest price in the range, whereas it should have defaulted to $55, the system marginal energy cost of the most economic supply (an export from CAISO) that was eligible to satisfy an additional increment of demand at the Silver Peak node—the ISO’s tariff definition of LMP. And this reasoning seems to be backed up by a review of congestion pricing at Silver Peak, presented by Eric Hildebrandt, director of the ISO’s department of market monitoring. <i>(See DBET Exhibit N.) </i></p>
<p>If all this sounds a bit convoluted, the reader might well prefer the much shorter narrative given by consultant Roy Shanker, testifying for the defense:</p>
<p>“The software is running the show, pricing is arbitrary, and CAISO is not following … the market design.”</p>
<h4>Derivatives on Trial</h4>
<p>So how do we arrive at the notion, urged by the defense, that FERC’s investigation in the Deutsche Bank case threatens the foundation of markets?</p>
<p>First, understand that when the commission promulgated its current price manipulation rule, more than five years ago, it borrowed its definition of fraud from the same case-law precedent that prevails in securities regulation:</p>
<p>“The commission defines fraud generally, that is, to include any action, transaction, or conspiracy for the purpose of impairing, obstructing or defeating a well-functioning market.” <i>(See Order 670, ¶50, Dkt. RM06-3, Jan. 19, 2006, 114 FERC ¶61,047.) </i></p>
<p>Under that definition, FERC need not prove an actual intent to manipulate prices. Instead, it could be enough simply to show that a transaction was conducted improperly, such as Deutsche Bank’s mistaken characterization of its physical transactions as “wheel-throughs.” Or even to show a coupling of unprofitable day-ahead trades (such as DBET’s physical schedules) with positions in financial derivatives (CRRs or FTRs), which could be interpreted as “impairing” or “obstructing” markets.</p>
<p>By contrast, the Deutsche Bank defense team argues that simultaneous trading in both physical and financial markets shouldn’t imply manipulation unless FERC can find that the actor was trading “against interest.” That test, the defense argues, is one that FERC has applied in the past. <i>(See, DC Energy v. HQ Energy Servs, Dkt. EL07-67, Sept. 29, 2008, 124 FERC ¶61,295.) </i></p>
<p>In particular, however, Hogan suggests that FERC’s enforcement office is mistaken in its concern over simultaneous physical and congestion trading.</p>
<p>As Hogan explains, financial derivatives such as FTRs and CRRs are tied inexorably to the capabilities of the grid. They must be simultaneously feasible under the condition of the security-constrained, market-clearing, least-cost dispatch solution, or else they can’t be adequately funded by RTO-ISO LMP revenues.</p>
<p>Stated differently, FTRs and CRRs are grounded in physics and bounded by volume; thus, regulators shouldn’t view them in the same light, for example, as the credit default swaps that proved so toxic during the recent credit panic of 2007 through 2009.</p>
<p>In fact, this very real ceiling that the physical grid places on trading electricity congestion rights lies at the heart of why the Commodity Futures Trading Commission is now considering whether to grant a petition filed earlier this year by the nation’s ISOs and RTOs, seeking an exemption from Dodd-Frank requirements for FTRs and CRRs. <i>(See, CFTC, Notice of Proposed Order and Request for Comment, 77 Fed. Reg. 52,138, Aug. 28, 2012.) </i></p>
<p>Yet Shanker fears the cat already is out of the bag, as he finds the implications of the Deutsche Bank case impossible to ignore:</p>
<p>“In my practice, since the commencement of the Enforcement investigation of the DBET trades, I have had to offer highly conditioned advice … to other parties seeking to execute what I would consider straightforward, profitable transactions.</p>
<p>“The chilling effect isn’t imagined; it is real and has already occurred.”</p>
</div></div></div><div class="field field-name-field-article-category field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Category (Actual): </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/article-categories/ferc">FERC</a></li><li class="taxonomy-term-reference-1"><a href="/article-categories/etrm-markets">ETRM &amp; Markets</a></li><li class="taxonomy-term-reference-2"><a href="/article-categories/transmission">Transmission</a></li></ul></div><div class="field field-name-field-members-only field-type-list-boolean field-label-above"><div class="field-label">Viewable to All?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-article-featured field-type-list-boolean field-label-above"><div class="field-label">Is Featured?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-department field-type-taxonomy-term-reference field-label-above clearfix"><h3 class="field-label">Department: </h3><ul class="links"><li class="taxonomy-term-reference-0"><a href="/department/commission-watch">Commission Watch</a></li></ul></div><div class="field field-name-field-image-picture field-type-image field-label-above"><div class="field-label">Image Picture:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1212-CW.jpg" width="1200" height="800" alt="" /></div></div></div><div class="field field-name-field-fortnightly-40 field-type-list-boolean field-label-above"><div class="field-label">Is Fortnightly 40?:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-law-lawyers field-type-list-boolean field-label-above"><div class="field-label">Is Law &amp; Lawyers:&nbsp;</div><div class="field-items"><div class="field-item even"></div></div></div><div class="field field-name-field-tags field-type-taxonomy-term-reference field-label-above clearfix">
<div class="field-label">Tags:&nbsp;</div>
<div class="field-items">
<a href="/tags/deutsche-bank">Deutsche Bank</a><span class="pur_comma">, </span><a href="/tags/price-manipulation">price manipulation</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/crr">CRR</a><span class="pur_comma">, </span><a href="/tags/congestion-revenue-rights">congestion revenue rights</a><span class="pur_comma">, </span><a href="/tags/ftr">FTR</a><span class="pur_comma">, </span><a href="/tags/financial-transmission-rights">financial transmission rights</a><span class="pur_comma">, </span><a href="/tags/constellation-energy-commodities-group">Constellation Energy Commodities Group</a><span class="pur_comma">, </span><a href="/tags/john-estes">John Estes</a><span class="pur_comma">, </span><a href="/tags/skadden-arps-slate-meagher-flom-0">Skadden Arps Slate Meagher &amp; Flom</a><span class="pur_comma">, </span><a href="/tags/dbet">DBET</a><span class="pur_comma">, </span><a href="/tags/cecg">CECG</a><span class="pur_comma">, </span><a href="/tags/silver-peak">Silver Peak</a><span class="pur_comma">, </span><a href="/tags/william-hogan">William Hogan</a><span class="pur_comma">, </span><a href="/tags/bill-hogan">Bill Hogan</a><span class="pur_comma">, </span><a href="/tags/unbundled">Unbundled</a><span class="pur_comma">, </span><a href="/tags/roy-shanker">Roy Shanker</a><span class="pur_comma">, </span><a href="/tags/software">software</a><span class="pur_comma">, </span><a href="/tags/degeneracy">degeneracy</a><span class="pur_comma">, </span><a href="/tags/locational-marginal-price">Locational marginal price</a><span class="pur_comma">, </span><a href="/tags/lmp">LMP</a><span class="pur_comma">, </span><a href="/tags/california-iso">California ISO</a><span class="pur_comma">, </span><a href="/tags/caiso">CAISO</a><span class="pur_comma">, </span><a href="/tags/e-tags">E-Tags</a><span class="pur_comma">, </span><a href="/tags/sierra-pacific-power">Sierra Pacific Power</a><span class="pur_comma">, </span><a href="/tags/summit">Summit</a> </div>
</div>
Fri, 30 Nov 2012 17:16:45 +0000puradmin16366 at http://www.fortnightly.comPJM/Midwest Market: Two Rival Groups Battle Over Grid Pricinghttp://www.fortnightly.com/fortnightly/2004/12/pjmmidwest-market-two-rival-groups-battle-over-grid-pricing
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Should transmission owners get paid extra for distance and voltage?</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Bruce Radford</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><strong>Bruce W. Radford</strong> is editor in chief of <em>Public Utilities Fortnightly</em>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - December 2004</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/0412-CW-table1.jpg" width="670" height="1231" alt="Table 1 - Transmission Cost Allocation — Regional Plan" title="Table 1 - Transmission Cost Allocation — Regional Plan" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/0412-CW-table2.jpg" width="1338" height="1395" alt="Table 2 - ExtraZonal Allocations — Regional Plan" title="Table 2 - ExtraZonal Allocations — Regional Plan" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>While the Midwest now appears set on competitive bidding for the electricity commodity, taking from PJM such tried-and-true elements as locational marginal pricing (LMP), financial transmission rights (FTRs), and a day-ahead market with a security-constrained dispatch, the region remains split over the pricing of transmission.</p>
<p>The fight centers on the network of ultra-high-voltage transmission lines built years ago by American Electric Power (AEP). Who should pay for that network under a market regime? The dispute asks no less of federal regulators than how to divvy up the profits and spoils of electric restructuring across geographic regions and industry sectors.</p>
<p>J. Craig Baker, senior vice president at American Electric Power, says it's only fair to give credit to utilities and ratepayers for the value they have added to the transmission network: "Utilities that have invested in strong and highly interconnected transmission systems bring valuable assets that contribute significantly to the expansion of markets."</p>
<p>But on the other side, consultant Roy Shanker talks of a world ruled by commodity prices, as in PJM, New York, and New England, where the LMP at any given node defines the worth of the underlying grid assets: "Locational marginal prices coupled with financial transmission rights," he says, "these are the key economic signals. The basic energy markets are the best tool for reflecting the regional value of transmission."</p>
<p>But if the Federal Energy Regulatory Commission (FERC) can produce net savings by forging a huge power market from the Dakotas to the Atlantic, then Baker and AEP want a piece of that pie, to reward their shareholders (and ratepayers) for building a high-voltage network. They fear that if FERC dictates a classic PJM market design, with transmission not priced according to distance, voltage, or usage, that the power producers and consumers who export and import low-cost power-moving west to east-will corner all the gain.</p>
<h4><b>The Two Rival Plans</b></h4>
<p>Of two rival groups, one favors a license-plate regime, with consumers paying grid charges reflecting only the allocated cost of the lines owned by its native utility within its local control area. Consumers would cover that cost even if it included excess capacity. But they would not pay for any faraway high-voltage lines owned by other utilities, even if they used them to import power. This plan, known as the "Unified Plan," would echo the same basic pricing method already in use by the PJM grid operator. The grid access charge reflects the embedded cost of service of the lines located in the zone in which the load sinks. Unified Plan supporters include Alliant, Cinergy, most of the original transmission-owning members (TOs) of PJM, plus several stand-alone TOs, including ATC (in Wisconsin), ATSI (the FirstEnergy grid spinoff), International Transmission (DetEd spinoff), and Michigan Electric Transmission (formed from Consumers Power). (<i>See FERC Dkt. Nos. ER05-6, EL02-111, EL03-212, EL04-135, filed Oct. 1, 2004.</i>)</p>
<p>The other group proposes a variation of a method known as "highway-biway," but blended with a flow-based allocation. This idea, known as the "Regional Plan," would force a different sharing of savings earned from restructuring. Regional Plan supporters include AEP, Exelon, Allegheny Power, Ameren, Illinois Power, and LG&amp;E. This minority group represents only 23 percent of the TO utilities in MISO and PJM,<b><sup>l</sup></b> but 40 percent of the value grid assets, and fully 55 percent of grid facilities rated at 345 kV or above. (<i>See FERC Dkt. Nos. EL02-111, EL03-212, EL04-135, filed Oct. 1, 2004.</i>)</p>
<p>By allocating grid costs based on voltage and usage, as per the Regional Plan, East-Coast consumers who import cheaper power from the Dakotas would pay some of the cost of the high-voltage and heavily used lines used to transport that power, wherever those lines might be located. Customers residing in Ohio or Kentucky, who take utility service from AEP, with its extensive array of high-cost, high-voltage lines, would receive compensation for the investment that their utility has made in the grid. They would now pay a lesser transmission charge, since they could throw off a portion of their grid costs to consumers in other areas who rely on those lines.</p>
<p>The Unified Plan represents the safe and familiar. The plan's proponents tout it as simple, convenient and workable-a "stable platform" on which to build a new power market in the Midwest, drawing on the experience gained from its use in PJM.</p>
<p>By contrast, the Regional Plan requires complex software to estimate the ever-changing flows of power across the grid, and to allocate costs accordingly. Yet proponents say the Regional Plan would apply long-accepted principles of rate making to achieve a fair and logical allocation of transmission costs.</p>
<h4><b>Cost Allocations</b></h4>
<p>Witnesses have estimated the total cost of service (TCOS) for transmission assets that would participate in the combined MISO/PJM market at $3.469 billion. The parties in the case have entertained a number of different possible methods of allocating those costs across the entire market, to design a rate for transmission access:</p>
<p><b>1. License-Plate Pricing.</b> Treat all grid assets as serving local needs; allocate all costs by zone (control area) so that grid prices vary from zone to zone. Consumers who reside and receive power in any particular zone pay transmission rates designed to cover the costs of lines owned by the utility that serves that zone.</p>
<p><b>2. Postage-Stamp Pricing.</b> Charge a single uniform access charge across the market, determined by dividing TCOS by total load served, yielding a rate of about $1.68/kW-month.</p>
<p><b>3. Highway-Biway Pricing. </b>Divide all grid assets into two classes by voltage (high-voltage is "highway"; low-voltage is "biway"). Treat biway lines as local, and allocate as per method #1. Treat highway lines as serving regional needs, and spread costs over total market load, as per method #2. Take a weighted average of the two elements to the grid access charge in any zone.</p>
<p><b>4. Flow-Based (Usage) Pricing.</b> Using a software program such as GE MAPS, estimate the power flows necessary to achieve a least-cost dispatch over the entire market area, and compare such flows to the "base-case" flows that would prevail if all consumers took generation supply only from plants and resources located in their local zone. The difference represents the degree of power flows attributable to regional needs throughout the market area (for exports and imports). Measure the cost of grid assets required to achieve those flows and serve those regional needs, and spread the cost across total regional load (in the same manner as highway assets are allocated as per method #3).</p>
<p>In its full level of detail, the Regional Plan would allocate costs under a blending of methods 1, 3, and 4. For transmission lines deemed to be dedicated to region-wide economic transactions, the plan allocates costs across zones with separate usage-based and voltage-based formulas, with a 50-percent weighting for each method. Smaller lines dedicated to local reliability would follow the traditional license-plate allocation. The plan proponents estimate that a market-wide cost allocation something like that shown in Table 1.</p>
<h4><b>Critics and Cost Shifts</b></h4>
<p>Note that the Regional Plan would create winners and losers among utilities (zones) across the MISO/PJM footprint. Table 2, derived from a presentation prepared jointly by the Wisconsin Public Service Commission and the Minnesota Department of Commerce, shows what portion of the grid assets in each transmission zone that would be treated as serving regional needs, and thus reallocated to consumers elsewhere. It also shows how much that consumers native to any particular zone would save (or pay extra) under the Regional Plan, as opposed to a strict postage-stamp method for allocating the cost of lines having a regional character.</p>
<p>As can be seen, native retail ratepayers of ComEd, AEP, and Illinois Power would see a significant amount of native grid costs reassigned to consumers in other areas. But so would the "classic" PJM utilities (the original transmission owning utilities in PJM, as before the admission of Allegheny Power, AEP, ComEd, Dominion, Dayton Power &amp; Light, etc.). These re-assigned costs would represent lines deemed to serve a market-wide purpose of facilitating power exports and imports.</p>
<p>By contrast, as the Wisconsin and Minnesota regulators point out, utilities and ratepayers in some zones would pay more in transmission rates than they would if the costs of these market-serving lines were allocated according to simple load shares.</p>
<p>Critics assail the Regional Plan also for its reliance on proprietary software (the GE MAPS program) to estimate the grid-flow dynamics required to achieve a least-cost, security-constrained dispatch. They question whether the software has access to reliable data on the costs and capabilities of power plants. And the Unified Plan sponsors observe that a rate design taken from the Regional Plan would force a continuing recalculation of line voltages and power flows, such as if a new TO should join one of the RTOs in the combined market area.</p>
<p>Nevertheless, the most troubling criticism observes that the Regional Plan engages in a recalculation of revenue requirement for transmission rates when, from a strict point of view, the FERC had asked the parties only to reconsider rate design.</p>
<p>Back in late September, FERC had opened a new proceeding to investigate and implement a new long-term pricing structure intended to eliminate seams in the combined region marked by the PJM and MISO RTOs. (<i>See, Docket EL04-135, 108 FERC ¶61,313.</i>)</p>
<p>In particular, FERC had required the elimination of pancaking "through-and-out" surcharges on transmission rates billed for crossing service territory boundaries, whether imposed by the RTOs (regional T&amp;O rates, or "RTORs"), or by the individual utilities. As part of the deal to remove the T&amp;O pancakes, FERC promised to make utilities whole over the short term by allowing a compensatory and temporary true-up charge (the SECA, or "Seams Elimination Cost Adjustment"). And to craft the SECA, FERC opened a broad settlement process, aimed at unifying the transmission price structure across the entire MISO/PJM area.</p>
<p>Thus, some Unified Plan proponents see the Regional Plan, with its flow-based pricing, as creating a stealth substitute to the old regime of T&amp;O rates. Instead of pancaked charges that apply when power crosses boundary lines between control areas and utility service territories, they see a new regime of voltage- and usage-based charges that will increase transmission rates for many ratepayers-leaving them no better off than before, when they paid T&amp;O rates.</p>
<p><em>Related: See <a href="http://www.fortnightly.com/fortnightly/2004/12/regulatory-roundup">Regulatory Roundup</a> by Bruce W. Radford.</em></p>
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<a href="/tags/aep">AEP</a><span class="pur_comma">, </span><a href="/tags/alliant">Alliant</a><span class="pur_comma">, </span><a href="/tags/ameren">Ameren</a><span class="pur_comma">, </span><a href="/tags/american-electric-power">American Electric Power</a><span class="pur_comma">, </span><a href="/tags/aps">APS</a><span class="pur_comma">, </span><a href="/tags/atc">ATC</a><span class="pur_comma">, </span><a href="/tags/central-maine-power">Central Maine Power</a><span class="pur_comma">, </span><a href="/tags/charles-river-associates">Charles River Associates</a><span class="pur_comma">, </span><a href="/tags/cinergy">Cinergy</a><span class="pur_comma">, </span><a href="/tags/citi">Citi</a><span class="pur_comma">, </span><a href="/tags/comed">ComEd</a><span class="pur_comma">, </span><a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/communication">Communication</a><span class="pur_comma">, </span><a href="/tags/consumers-power">Consumers Power</a><span class="pur_comma">, </span><a href="/tags/cost">Cost</a><span class="pur_comma">, </span><a href="/tags/dayton-power-light">Dayton Power &amp; Light</a><span class="pur_comma">, </span><a href="/tags/dominion">Dominion</a><span class="pur_comma">, </span><a href="/tags/duke-energy">Duke Energy</a><span class="pur_comma">, </span><a href="/tags/electric-transmission">Electric Transmission</a><span class="pur_comma">, </span><a href="/tags/exelon">Exelon</a><span class="pur_comma">, </span><a href="/tags/fcc">FCC</a><span class="pur_comma">, </span><a href="/tags/federal-communications-commission">Federal Communications Commission</a><span class="pur_comma">, </span><a href="/tags/federal-communications-commission-fcc">Federal Communications Commission (FCC)</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission-ferc">Federal Energy Regulatory Commission (FERC)</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/firstenergy">FirstEnergy</a><span class="pur_comma">, </span><a href="/tags/ge">GE</a><span class="pur_comma">, </span><a href="/tags/illinois-commerce-commission">Illinois Commerce Commission</a><span class="pur_comma">, </span><a href="/tags/iso">ISO</a><span class="pur_comma">, </span><a href="/tags/iso-new-england">ISO New England</a><span class="pur_comma">, </span><a href="/tags/iso-ne">ISO-NE</a><span class="pur_comma">, </span><a href="/tags/lge">LG&amp;E</a><span class="pur_comma">, </span><a href="/tags/lmp">LMP</a><span class="pur_comma">, </span><a href="/tags/locational-marginal-price">Locational marginal price</a><span class="pur_comma">, </span><a href="/tags/locational-marginal-prices">Locational marginal prices</a><span class="pur_comma">, </span><a href="/tags/maine-puc">Maine PUC</a><span class="pur_comma">, </span><a href="/tags/maps">MAPS</a><span class="pur_comma">, </span><a href="/tags/miso">MISO</a><span class="pur_comma">, </span><a href="/tags/new-jersey">New Jersey</a><span class="pur_comma">, </span><a href="/tags/ohio-edison">Ohio Edison</a><span class="pur_comma">, </span><a href="/tags/pge">PG&amp;E</a><span class="pur_comma">, </span><a href="/tags/pjm">PJM</a><span class="pur_comma">, </span><a href="/tags/questar">Questar</a><span class="pur_comma">, </span><a href="/tags/renewable">Renewable</a><span class="pur_comma">, </span><a href="/tags/renewable-energy">Renewable Energy</a><span class="pur_comma">, </span><a href="/tags/rto">RTO</a><span class="pur_comma">, </span><a href="/tags/transmission">Transmission</a><span class="pur_comma">, </span><a href="/tags/utah-public-service-commission">Utah Public Service Commission</a><span class="pur_comma">, </span><a href="/tags/wisconsin-public-service">Wisconsin Public Service</a> </div>
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Wed, 01 Dec 2004 05:00:00 +0000puradmin11124 at http://www.fortnightly.com